US 20040129428 A1
This invention provides a method to efficiently remove liquids—hydrocarbons or water—from a natural producing formation so as to reduce the resistance to gas inflow to the wellbore from the formation. The system will also serve as an efficient mechanism for producing hydrocarbon liquids by operating at a higher wellbore and near-wellbore formation pressure to maintain such liquids in a state of increased mobility due to the retained gas in solution. The system used is a downhole device containing a float-operated valve, said float being sensitive to fluid filling its interior such that it falls with liquid fill, opening a valve to the production tubing string liquids are allowed into the production tubing, while gas is produced up the tubing-casing annulus. A unique combination of artificial lift is incorporated in the tubing string, basically a plunger lift operated by one or more gas lift valves that open when a prescribed column of liquid is sensed above the valve. A venturi-type nozzle above the gas lift valve acts to disperse the gas bubbles to create a more efficient fluid slug to lift the plunger to surface.
1. A method of increasing production and ultimate recovery of gaseous and liquid hydrocarbons from one or more downhole natural gas baring formations and through a production tubing string within a wellbore by complete removal of liquids from the wellbore and utilizing gas pressure drive of a natural gas baring formation, the method comprising:
the wellbore being perforated for liquid and gaseous hydrocarbon production in a gas baring formation;
providing a surface gas flow pressure regulator and a surface pressure gauge on the casing well head annulus exit port for respectively regulating gas flow production and measuring pressure white maintaining a predetermined flow pressure on the wellbore annulus;
positioning a downhole shrouded cover injector at the bottom of a production tubing string relative to the opened formation;
passing formation fluids through the downhole injector by pressure differential and through the production tubing string toward the surface while preventing formation gases from entering the production tubing string;
positioning a plunger lift within a production tubing string above the injector for lifting liquids to the surface;
positioning one or more fluid operated gas lift valves for lifting liquid to the surface by gas injection into the tubing string below the plunger lift;
plunger lifting liquid inflow efficiently by maintaining a gas fluid interface between plunger and liquid through the production tubing string to the surface of the well; and
maintaining direct fluid communication between the wellbore and the opened gas baring formation and liquids entering from the lower part of the formation, such that such gas pressure acts as a cap on the formation fluids in the opened formation to force the fluids out of the formation into the wellbore through the injector and toward the surface.
2. The method as defined in
wherein the downhole injector is positioned relative to the lowest downhole opened gas baring formation in the wellbore so that all incoming liquid hydrocarbons and invading waters are efficiently and completely removed from the wellbore into the lower pressure production tubing string on to the surface thereby considerably increasing gaseous and liquid hydrocarbon recovery.
3. The method as defined in
continually and comparatively measuring and monitoring the formation gas flow production, pressure and related recovery for the most effective optimum gas flow pressure at the wells surface gas flow meter and periodically making and observing fluid level and gas-oil ratio test, while continually and comparatively measuring and monitoring the production and recovery of formation liquids through a surface metering facility for a combined total maximum gaseous and liquid hydrocarbon production and ultimate recovery throughout the reservoir's formations total gaseous and liquid hydrocarbon recovery life for maximum hydrocarbon reserve value.
4. The method as defined in
while recovering formation liquids at the surface production tubing string discharge, simultaneously flowing formation gas production and pressure at a regulated and controlled predetermined gas flow pressure at the surface gas flow pressure regulator with the surface gas pressure gauge to retain an optimum formation gas pressure in an annulus about the production tubing string, and thereby on and within all opened hydrocarbon formations, such that the gas pressure prevents solution gas within the liquid hydrocarbon in its formation and the wellbore from breaking out of solution, thereby maintaining its expulsive force, high mobility and low viscosity, and acts as a driving force to pass pressured higher pressure hydrostatic head liquids out of the formation and through the injector by pressure differential on up into the lower pressure production tubing string to recover formation liquids at the surface, wherein total in place liquid hydrocarbons are maintained highly fluid and recoverable, thereby increasing related liquid hydrocarbon reserve value.
5. The method as defined in
maintaining a predetermined optimum formation gas flow pressure in the wellbore annulus such that gas pressure acts as a driving force on all liquid hydrocarbons and invading waters to pass them through the injector by pressure differential into the lower pressure production tubing string for formation fluid recovery at the surface, so that a liquid level is maintained in the wellbore at the injector liquid in take level for maximum free gas and pressurized fluid flow from all opened hydrocarbon formations for maximum gaseous and liquid hydrocarbon recovery, whereby total gaseous and liquid hydrocarbon reserve recoverability and related value is increased.
6. The method as defined in
maintaining a wellbore gas pressure in the annulus above the downhole injector intake liquid level as a driving force to maintain a predetermined liquid level in the lower pressure production tubing string for maximum plunger lift or other artificial lift efficiency of incoming liquids on to the surface.
7. The method as defined in
positioning a check valve within a production tubing string above the top of the injector for preventing fluids which pass by the check valve from returning to the injector; and
the injector housing having a nominal outer diameter, a fluid responsive float open at the top and closed at the bottom and moveable with respect to the injector housing as a function of fluid density surrounding the float, and a shut off valve member moveably responsive to the float for engagement with a shut off valve seat, the shut off valve member being spaced vertically below inside the injector housing from the check valve.
8. The method as defined in
providing in high formation sand influx wells a sleeve-shaped filter screen across an inlet flow port at the top of the liquid injector for restricting at least 90% of solid particles 30 microns or greater from passing through the filter screen, accumulating and closing the injector outer housing at the bottom.
9. The method as defined in
providing the surface gas flow pressure regulator for controlling gas flow from the wellbore annulus at the well head exit port throughout the complete production and total recovery of all in place liquid hydrocarbons until said production and recovery considerably declines, at such time converting over to maximum gas production by releasing the surface gas flow pressure to a lower predetermined optimum or open flow pressure at the surface gas flow regulator, to efficiently produce and recover natural gas white efficiently removing any incoming invading waters in the wellbore, whereby total in place liquid hydrocarbons have been recovered, leaving only the small quantities that stick to the formation rock pores as a thin film, and that are isolated in any formation structural traps, wherein total in place gas is free to flow to the surface for total in place natural gas production and recovery, thereby recovering total in place liquid and gaseous hydrocarbons maintained and converted by this recovery process to be ultimately recoverable.
 The present invention relates to the process of removing or producing liquids from the lower part of a vertical wellbore which is in communication with a liquid hydrocarbon producing and/or gas-producing reservoir via perforations, open hole, or horizontal boreholes. Such liquids, if not removed, will restrict the inflow of natural gas and liquid hydrocarbons by accumulating uphole within the wellbore while their increasing hydrostatic pressure decreases the effective pressure differential needed by liquid hydrocarbon and/or natural gas in the near-wellbore formation to flow from the reservoir into the wellbore. This new liquid removal process “deliquefying system” by being completely effective in continuously removing all liquids from the wellbore, keeping them off the oil and/or gas-producing zone, would allow optimum production and recovery of liquid hydrocarbons and/or natural gas into the wellbore at the lowest producing bottomhole pressure allowed by the well's particular producing system. This advance in liquid removal will notably increase liquid hydrocarbon and/or natural gas recovery in total volume and daily production from a liquid hydrocarbon and/or gas-bearing reservoir due to its complete liquid removal process.
 Concerning natural gas wells, the industry presently utilizes many systems for removing liquids from gas wells, predominantly by sucker-rod, or other types of pump lift, and various types of gas-lift and plunger-lift methods, typically using a production tubing string as the liquid-removal conduit, while gas is produced from the tubing-casing annulus.
 In all of these presently used methods, in both oil wells and gas wells, a portion of the desired reservoir gas can become part of the total fluid flow entering the production tubing removal string, with negative effects on liquid-removal efficiency. Also, any substantial volume of liquid accumulation will seriously effect daily liquid hydrocarbon and/or gas production by temporarily or repeatedly blocking the liquid hydrocarbon and/or gas producing interface of the wellbore. The proposed combination of plunger-lift with gas-lift valve and a shrouded float-controlled device liquid injector, (the liquid removal system) will allow only liquid hydrocarbons and/or waters into the production tubing string to consistently remove essentially all liquids as they enter the lower wellbore, thus maintaining the formation interface dry for optimum liquid hydrocarbon and/or gas flow and production.
 The present invention discloses a more effective application for plunger-lift with one or more fluid-operated gas-lift valves to introduce controlled lift gas. Liquids only are admitted to the tubing string for removal by a float-operated device, the liquid injector, that positively prevents the entry of free gas or highly gas-cut, or “foamy” liquid hydrocarbon into the production tubing, but opens to allow entry of water or hydrocarbon liquids. Also described is a venturi tube addition to a gas-lift operation to increase the effidency of gas in lifting a liquid column. However, no published data have revealed a oil or gas-well deliquefying system and method in which a downhole shrouded float operated valve has been used in conjunction with gas lift operating under plunger lift to create a relatively gas-free column of liquid within the tubing string, then lift that liquid column to surface above a plunger driven by annular gas entering the tubing through a tubing-pressure actuated gas lift valve or valves. The basic function and claimed improvement of the plunger system, which is available and in use within the oil and gas industry is to provide an interface between gas-lift gas and the incoming liquid being lifted, is to prevent breakthrough of the gas into and up through the liquid. Gas lift valves are also available that will detect a preset liquid pressure column created by a level within the tubing and open the valve to inject annulus gas into the liquid column under the plunger.
 The present invention uses a downhole oil liquid injector (DOLI) that uses a float operated valve, to introduce liquids into the production tubing string. The DOLI is also disclosed in U.S. patents issued, U.S. Pat. No. 6,089,322 (Jul. 18, 2000), U.S. Pat. No. 6,237,691 B1 (May 29, 2001), U.S. Pat. No. 6,325,152 B1 (Dec. 4, 2001), U.S. Pat. No. 6,622,791 B2 (Sep. 23, 2003), and U.S. patent Pending Ser. No. 10/664,784 (filed Sep. 17, 2003) of which the inventor of the present invention is also an inventor or co-inventor. The present invention can substantially benefit liquid lift and overcome bottomhole wellbore casing size restrictions by its use of plunger lift and a thin shrouded protected cover respectively, in certain scenarios of the foregoing patents/patents pending.
 The present invention discloses an improved natural gas-well deliquefying system to produce or remove the accumulation of liquids, such as fresh water, salt water, crude oil, or condensate as they enter the wellbore that is directly below the producing formation. A principal part of the control for both producing valuable liquid hydrocarbons, removing incoming detrimental waters while producing or retaining natural gas flow, is a casing surface well head standard gas flow regulator valve and its pressure gauge. The pressure flow regulator gives control over desired or needed casing annulus gas back pressure.
 Incoming liquids, water, or hydrocarbon, if not completely removed, will build up within the wellbore and the adjacent reservoir, resulting in an increase in hydrostatic pressure that will decrease the pressure differential from formation to wellbore and thus retard the inflow of liquid hydrocarbons and/or natural gas and thus decrease desired and ultimate liquid hydrocarbon and/or natural gas production and recovery. In natural gas wells with already tow reservoir pressures, the added restriction to gas inflow can cause a significant production loss, or even “log-in” killing the well's gas flow, thus losing total recovery of natural gas and liquid hydrocarbons in place.
 In gas wells, typical liquid removal systems in use include: 1) slowly pumping the liquid off through the production tubing string with a sucker-rod pump system while maintaining a liquid level above the pump intake; 2) use of gas lift to inject gas from the tubing-casing annulus into the tubing in timed, or otherwise controlled, cycles, to lift slugs of liquids to surface; 3) in high pressure wells, flowing gas up the tubing string with slugs of liquids; 4) addition of plunger lift systems in the tubing to lift liquid with gas flow below. The tatter systems are commonly operated by control systems which open valves to remove the lifted liquid slugs and release plunger catching systems in the well head to allow the plunger to drop back to its bottomhole location, where its velocity impact is controlled by a bumper spring. Principal limitations of the present deliquefying systems noted are related to the inefficiencies created by mixing the liquids with the produced gas, and/or inability to predict and control the timing of automated gas-lift and plunger-lift systems. A major limitation of pumping liquids is the common problem of gas locking in sucker-rod pumps. In medium to high volume liquid accumulation burdened gas wells, liquids interfere with the gas production interface continually or periodically, seriously restricting gas flow production and recovery with all the above.
FIG. 1 illustrates schematically, from bottom to top, the deliquefying system. The shrouded float with valve device (1) is shown on the bottom. Above is the standing valve (6). The fluid-operated gas-lift valve on outside mandrel (7) is shown. The venturi tube (8) is shown and the plunger-lift (10) with bumper spring stop (9) is shown.
FIG. 2 illustrates schematically the shrouded float-operated valve device. Within the outer shroud, which is supported by fin-like hangers attached to the discharge tube which, in turn, leads to an attachment to the bottom of the tubing string, as seen in FIG. 1. The shrouded float operates within permanent liquid fill within a “rat hole ” below the bottom of the producing formation. The two-stage valve shown comprises a pilot valve directly connected to the bottom of the float which—when the float drops with liquid fill—opens a small diameter port through the main valve to equalize pressure differential between wellbore and tubing. As the float submerges a short distance, the pilot tip applies full float weight to the main valve to complete its opening.
FIG. 3 illustrates schematically from bottom to top, the deliquefying system where the shrouded float and valve device cover is now replaced with a steal outer jacket that is closed at the bottom and opened at the top via perforations with an outer sand screen for sand influx where liquid inflow enters the tool to exit through the opened valve attached to the float device. The standing valve (6), and the fluid operated gas lift valve on outside mandrel (7) and venturi tube (8) with plunger-lift (10) and bumper spring stop (9) is the same as shown is FIG. 1.
 The present invention discloses a more efficient liquid lift deliquefying system which provides an improved positive solution to the limitations of presently available liquid lift gas-well deliquefying systems. The method disclosed utilizes a thin shrouded float-operated downhole valve system (FIG. 1, 1), the liquid injector, that detects presence of gas or highly gas-cut foamy liquids in the production fluid within the wellbore and closes the entry valve (4) into the production tubing string by buoyancy. If formation sand influx prohibits the use of an opened shrouded cover, then an inclosed outer steal jacket liquid injector, perforated and screened at the top and closed at the bottom, as seen in FIG. 3, will be used. As liquid inflow continues and the liquid level (LL) rises in the wellbore, the float system responds by filling and submerging, thus opening the valve (4). Thus, at all times, only liquid hydrocarbons, with any contained gas essentially in solution, or waters will be allowed to flow into the tubing. And the liquid level (LL) in the wellbore, i.e., the gas-liquid interface, will essentially remain at the entry level of the top of the traveling float (3). As shown in FIG. 1, the downhole shrouded, or enclosed as needed, float-operated valve system (1), the liquid injector, would be located within the wellbore substantially below the top of the production formation (F), so that the liquid would be continually removed from essentially all of the formation face, drawing liquids directly from, thereby preventing their buildup in, the surrounding reservoir.
 The present invention combines the ability of the system to produce liquids only into the tubing string with a novel combination of systems for removing said liquids from the tubing, including the use of a casing wellhead surface flow regulator valve to hold desired back pressure or open flow on the casing annulus. When the float valve is open, liquids flow upward in response to available formation pressure and pass through the system's discharge tube (5), into the tubing string, then past a standing valve (6), above which a column of liquid is created in the tubing. The liquid removal system shown comprises a tubing-pressure actuated gas-lift valve in a conventional side-pocket mandrel (7), which alternatively can be inside mounted for small internal diameter (ID) casing. The gas-lift valve's internal bellows with stem and valve tip on seat is set to open at a pre-determined liquid level, i.e., its equivalent hydrostatic pressure, to open the valve to the tubing to allow annulus gas at producing-level pressure to flow into the liquid column.
 Above the gas-lift valve is located a venturi tube device (8), which, by its velocity flow through the inner tube creates a more efficient gas-liquid mixture and sweeping action forming a gaseous piston to help drive the liquid column upward. Use of the venturi system forms a control flow below the plunger for improved lift, ideally for average to larger diameter tubing, and is included, and claimed as a feature of the invention for a more highly effective gas-lift flow. Above the venturi, the plunger (10) is shown on the optimal spring-loaded bumper stop (9) which is affixed to the tubing with a special tubing sub. Ports through the bumper's lower connection allow passage of liquid and gas upward. As the plunger (10) rests on the bumper stop, slower moving liquid entering the tubing rises through the conventional clearance allowance around the plunger to achieve its desired height level. Various types of plungers can be used. Some have built-in bumper springs. However, as the surge of gas from the gas-lift valve through the venturi, forming a gaseous piston, contacts the plunger, the solid body of the plunger acts as an interface between gas and liquid to prevent the gas from blowing through the liquid and failing to lift it as an essentially solid mass. As the prescribed column of liquid is lifted, in deeper wells past one or more additional gas-lift valves spaced at higher levels and actuated, again, by increased internal tubing pressure, the liquid is lifted farther toward the surface and eventually into the well's tubing-flow surface receiving system, typically a low-pressure gas-liquid separator. Additional gas-lift valves for stage lift will be used in exceptionally deep wells, as needed, and are a claimed feature of the invention for more efficient liquid lift using a thin shrouded cover liquid injector to introduce only liquid flow to the tubing string.
 The present invention applies further to other combinations of the shrouded float-operated valve for liquid lifting systems. For example, liquid introduced into the tubing by the float and valve system could be continually lifted by most other artificial lift methods available in the industry, including a sucker-rod pump, with the essentially gas-free liquid preventing gas-locking and other related production lift gas-caused problems in the pump and pumping systems.
 Shrouded Float with Valve Operation
 The present invention illustrates a downhole shrouded float and valve device (1) that features several basic components. A thin shrouded protective cover without restrictions to its lengths as required, is provided so that liquid will travel downward which allows formation sand to settle out to the bottom, while produced gas travels upward in the annulus to be produced at surface. The thin shroud enables construction in smaller-OD sizes for many of the industry's smaller-diameter gas wells utilizing 4½-in. OD casing (which is a fraction less than 4-in. ID) (2). The shroud would be constructed of a thin lighter-weight steel, synthetic material or fiberglass, and suspended from the upper part of the discharge tube (5) or the bottom of the tubing string (T). Many gas wells have gradual liquid accumulation. Thus incoming sand with the liquid travels downward, settling out as the flow movement is slow. For low to average liquid volume producing wells, the shroud would be open at top and bottom, thus directing liquids downward and back up to the float inlet, in the process diverting incoming sands and debris downward. In high liquid volume wells with sand influx, if needed, a sand screen can be incorporated in the upper part of the shroud and a screen-type debris barrier added to the lower end or it can be completely enclosed. The float (3) is constructed of very light-weight steel, synthetic material, or fiberglass. It operates within the liquid always present in the wellbore and within the shroud, up to the top of the float. Until the liquid level (LL) inside float drops such that essentially free gas can enter the float, the float is full of liquid and thus drops to bottom to open the valve (4). Gas entry into the float increases float buoyancy within the surrounding liquid, until the float rises, shutting off the valve.
 The other principal feature of the system is the valve (4). In well systems operating under higher pressures, a substantial pressure differential is created between the nearly complete loss of tubing pressure in the tubing above the valve, when the liquid column is unloaded by gas-lift flow under the plunger lift and operating bottomhole annulus pressure. A high differential pressure could prevent the opening of the float-operated valve as the float falls. To alleviate this problem, a double valve (FIGS. 2 and 3) featuring a small-diameter pilot orifice valve (11) is used. This pilot valve opens first, which then equalizes the pressure differential across the larger-diameter main valve (12). In certain low-pressure gas wells, use of a single valve can be practical, with opening size determined by expected flow rate and pressure differentials, relative to the type of liquid column lift employed.
 The present invention will substantially increase total and ultimate recovery of inplace natural gas from producing gas-reserve reservoirs where incoming liquids, waters or liquid hydrocarbons (condensate and crude oil) seriously lower and/or hinder daily gas production and ultimate recovery. Further, if not immediately and completely removed, liquid accumulation will, in time, “log in” or kill producing gas wells as the reservoir's volume and pressure decrease, thereby prevent ultimate recovery of natural gas from reservoir wells. Also, the present invention, by promptly removing and producing all incoming liquids, including condensate and crude oil, notably increases production and recovery of valuable liquid hydrocarbons.
 As liquid accumulation is a common problem in the upstream natural gas producing industry, the liquid and gaseous hydrocarbon production and ultimate recovery benefits are claimed over all prior art as an advance and benefit for the U.S. and world oil and natural gas production industry.
 Other claims and improvements are evident, which include the aforementioned improved liquid and gaseous hydrocarbon recovery systems. The foregoing disclosure and description of the invention thus explanatory thereof will be appreciated by those skilled in the art, which is defined by the claims.